GENERAL INTERESTQuick Takes
Australia to raise transparency for offshore projects
The Australian government has announced there will be increased transparency for all environmental plans for offshore oil and gas activities. All plans will be published, and draft environment plans for offshore seismic and exploration drilling activities will be open for public comment under changes to environmental regulations.
Minister for Resources and Northern Australia Matt Canavan said the new requirements are part of a suit of changes to improve and increase transparency of the country’s offshore petroleum work. “Australians need to be confident that oil and gas activities being carried out offshore meet our stringent environment regulations, and that all environmental risks and impacts of the proposed activity are taken into account,” he said.
“The public will have a 30-day comment period to give feedback on the environmental management of proposed seismic and exploration drilling activities, providing a new level of accountability, Canavan said.
“Environment plans for all offshore activities will be published when they are submitted to the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) before they are assessed,” he added.
“If the plan is accepted by NOPSEMA, it will be published, along with an explanation of how public comments have been taken into account, enabling the community to see how their concerns have been addressed,” he said.
The new regulations will come into action on Apr. 25. All draft environment plans submitted from that date onwards will be published on the NOPSEMA web site, along with information on how to make comments on the plans.
Gazprom to acquire Kyrgyzneftegaz assets
Officials of state-owned Gazprom and the government of Kyrgyzstan have signed what they describe as a “roadmap” for the Russian company’s acquisition of the assets of Kyrgyzneftegaz.
Gazprom already is active in the Kyrgyz Republic, which has negligible oil and gas production.
A wholly owned subsidiary, Gazprom Kyrgyzstan, is the country’s only gas importer. It owns the Kyrgyz gas transmission and distribution systems.
Gazprom holds two exploration licenses in Kyrgyzstan for areas designated Kugart and Eastern Mailu-Suu IV.
Kyrgyz Petroleum Co., a wholly owned subsidiary of Kyrgyzneftegaz, operates a 10,000 b/d refinery at Jalal-Abad and conducts oil and gas exploration and development.
OGCI unit lets carbon-capture contract
Oil and Gas Climate Initiative Climate Investments has let a “multimillion-dollar” contract to Wood PLC for conceptual engineering in its gas power and industrial carbon capture work.
The project includes engineering and concept design for a full-scale gas power plant with carbon capture.
Its industrial carbon capture conceptual design initially will cover production of hydrogen, fertilizer, petrochemicals, cement, and steel.
Exploration & DevelopmentQuick Takes
Total signs HOA to explore Oman Block 12
Total SA and Oman’s Ministry of Oil and Gas have signed a heads of agreement for award to the French company of an exploration license covering Block 12 in Central Oman.
Total will hold a 100% interest in the 10,000-sq-km block. It’s south of Blocks 10 and 11, which Total has agreed to develop in an integrated gas project that includes construction and operation of a liquefaction plant and LNG bunkering.
The Block 12 program will include seismic data acquisition and drilling commitments, with the first well due in 2020.
Exxon, Ecopetrol sign contracts for Colombia blocks
ExxonMobil Corp. and Colombia’s Ecopetrol each signed a 50-50 joint contract individually with Repsol for offshore exploration and production in offshore blocks in the Caribbean Sea.
Repsol will remain the operator of the blocks—COL-4 and GUA-OFF-1. ExxonMobil is the partner in COL-4, and Ecopetrol is the partner in GUA-OFF-1.
COL-4 block is 60 miles north of Bolivar province. GUA-OFF-1 block is north of La Guajira province. Each block covers about 988,000 acres.
Colombia’s government recently amended its contract terms for offshore exploration.
Aker finds oil with Pecan South-1A well off Ghana
Aker Energy reported an oil discovery with its Pecan South-1A well on the Deepwater Tano Cape Three Points (DWT-CTP) block offshore Ghana. The Maersk Viking drillship will drill a sidetrack appraisal well, said block operator Aker.
The Pecan South-1A is south of Pecan field. Aker plans to finalize its development plan for the area by Mar. 30, said CEO Jan Arve Haugan. After drilling the Pecan South sidetrack well, the Maersk Viking drillship will relocate to drill an appraisal well in Pecan South East. Aker holds 50% interest in DWT-CTP block. Partners are Lukoil with 38%, Ghana National Petroleum Corp. 10%, and Fueltrade 2%.
Vedanta to appraise oil discovery in India
Vedanta Ltd.’s oil and gas unit plans to appraise an oil discovery in its H-2 well in the Krishna-Godavari basin on India’s East Coast. The well, on Block KG-OSN-2009/3, encountered multiple reservoir zones in a Mesozoic sequence at 3,310-4,026 m with hydrocarbon indications during drilling and downhole logging.
A zone at 3,403-3,431 m flowed oil to surface during a DST. The first exploration well on the block, A3-2, was a gas discovery.
Eni plans third development well for Blacktip gas field
Eni Australia has submitted environmental plans for a third production well on its wholly owned Blacktip gas and condensate field in the shallow waters of the southern Bonaparte Gulf off Northern Territory.
Blacktip, discovered in 2001, was brought on stream in 2009. The existing development comprises a fixed steel four-leg unmanned platform and two production wells connected to a subsea pipeline transporting gas and condensate to an onshore processing facility at Wadeye west of Darwin. Wadeye is connected by an onshore pipeline to the main grid.
The Wadeye facility consists of gas separation, dehydration, and compression equipment along with storage tanks for the condensate, which is periodically offloaded to seagoing tankers via a buoy 7 km offshore. Blacktip initial reserves were estimated at 150 million boe contained in stacked reservoirs of Lower Triassic and Permo-Carboniferous age.
Eni lets contract for Merakes development
Eni SPA has let an engineering, procurement, construction, transportation, and installation contract to TechnipFMC for development of deepwater Merakes natural gas field offshore Indonesia. The contract covers five wells in 1,500 m of water with 50-km tiebacks to the Jangkrik floating production unit in the Makassar Strait off East Kalimantan.
TechnipFMC will provide engineering, procurement, and installation of subsea equipment including trees, a manifold, large-bore, high-pressure flexible lines, umbilicals and distribution hardware, flexible risers, flowlines, and jumpers.
Eni received development approval in April 2018 for Merakes field, which is in the East Sepinggan production-sharing contract area.
The field is 35 km southwest of the Jangkrik FPU, which is in the Muara Bakau PSC area.
Eni estimates Merakes holds 2 tcf of lean gas in place in Pliocene sands of “world class reservoir quality.”
From the Jangkrik FPU, Merakes gas will flow through existing pipelines to the Bontang liquefaction plant operated by PT Badak in East Kalimantan. Production from the Jangkrik complex of fields began in 2017.
Eni East Sepinggan Ltd. holds an 85% participating interest in the East Sepinggan PSC. Pertamina Hulu Energy holds 15%.
Newfoundland and Labrador bid round opens
The Canada-Newfoundland and Labrador Offshore Petroleum Board has issued a call for bids for exploration licenses in two offshore areas.
Call for Bids NL19-CFB01 offers nine parcels covering a total of 2.270472 million hectares in the Southeastern Newfoundland Region.
Call for Bids NL19-CFB02 offers four parcels covering 464,877 hectares in the Jeanne d’Arc Region.
The only bidding criterion is the exploration spending commitment during the first phase of the 9-year license. The minimum work-commitment bid is $10 million (Can.).
Close of bidding is Nov. 6.
Chariot Oil & Gas adds acreage off Morocco
Chariot Oil & Gas Holdings (Morocco) Ltd. plans to reprocess 1,425-sq-km of 3D seismic data and assess development and exploratory potential of the Lixus license offshore Morocco.
The subsidiary of Chariot Oil & Gas Ltd., London, has been awarded the license and designated operator with a 75% interest, in partnership with the National Office of Hydrocarbons and Mines, with 25%.
Development would involve a 2009 discovery by a group led by Repsol YPF SA in the Anchois-1 well, drilled in 388 m of water 40 km offshore (OGJ Online, Mar. 30, 2009). The well cut two Tertiary intervals of high-quality, gas-bearing sands totaling 90 m, with net pay Chariot estimates at 55 m.
Chariot said the Anchois-1 reservoir sands occur above a nappe emplaced during the Alpine orogeny that exhibit “a characteristic and anomalous seismic signature.”
It has identified five satellite prospects with tie-back potential, the focus of its seismic reprocessing. It also will evaluate leads identified below the nappe. The 2,390-sq-km license extends from the coastline into 850 m of water. It’s 30 km north of Chariot’s existing Moroccan acreage.
Zhenis block off Kazakhstan due drilling
Zhenis Operating, a 50-50 joint venture of Lukoil and KazMunayGas, will drill an exploration well and shoot a 3D seismic survey on the Zhenis block in the Caspian Sea offshore Kazakhstan. The partners have signed a contract for exploration and development on the block with the Kazakh Ministry of Energy. The block is 80 km offshore. Aktau is the nearest port.
Drilling & ProductionQuick Takes
Gazprom Neft expands oil production in Kurdistan
Gazprom Neft Middle East BV has commissioned a third production well in Sarqala field in the Kurdistan region of Iraq.
Potential production from Sarqala-3 is estimated at 12,000 b/d of oil. Cumulative production from the field has reached 35,000 b/d, a 25% increase.
Drilling of Sarqala-3 to TD of 3,291 m involved an international team with members from 20 countries. Anomalously high pressure and reservoir temperature demanded the use of 11 technological solutions, the company said.
Construction involved the use of large-diameter casing pipes with ultra-strong thread connections, weighted drilling mud for bottom-hole flushing, and cement incorporating mineral-based and iron-oxide additives. The project was implemented by Gazprom Neft Middle East, with support from the Gazprom Neft Science & Technology Centre.
Lapa field consortium lets subsea contract
The Lapa field consortium has let a subsea contract to TechnipFMC for Lapa field on Block BM-S-9A in the Santos presalt basin in 2,150 m of water 270 km off Sao Paulo, Brazil.
Consortium partners are Total E&P do Brasil Ltda. 35%, Shell Brasil Petroleo Ltda. 30%, Repsol Sinopec Brasil SA 25%, and Petroleo Brasileiro SA (Petrobras) 10%.
The contract covers the supply of flexible pipes for oil production, gas lift, and gas injection as well as associated accessories. The field will be connected to the 100,000-b/d Cidade de Caraguatatuba floating production, storage, and offloading vessel, already in operation.
Lapa field began production in December 2016 via the FPSO, which, alongside its crude production, can store 1.6 million bbl of oil and compress 5 million cu m/day of gas.
TechnipFMC values the contract at $75-250 million.
In January 2018, Petrobras transferred most of its ownership interest in, as well as operatorship of, Lapa field to Total.
Inpex lets drilling contract for Ichthys field
Inpex Australia has contracted Maersk Drilling’s Maersk Deliverer ultradeepwater semisubmersible rig for work on the Ichthys gas-condensate field in the Browse basin off northwestern Western Australia. The 3-year contract is valued at $300 million and includes mobilization as well as two 1-year options.
Maersk said the contract is expected to begin during second-quarter 2020. The rig is currently operating offshore Timor Leste. Ichthys field lies in 250 m of water about 220 km offshore. The field contains an estimated 12 tcf of gas and 500 million bbl of condensate. Gas production started from the field in July 2018. First condensate loading took place from the offshore location in early October 2018 and first LNG shipment from the Darwin plant came later the same month.
At peak the project will produce 8.9 million tonnes/year of LNG, 1.6 tpy of LPG, and 100,000 b/d of condensate.
PROCESSINGQuick Takes
Idemitsu Kosan finalizes integration of refiner
Idemitsu Kosan has completed its long-planned takeover of Japanese refiner and marketer Showa Shell Sekiyu KK (OGJ Online, Dec. 19, 2016). The consolidation was finalized on Apr. 1.
Under the business integration plan, the Shell unit has become a wholly owned subsidiary of Idemitsu Kosan.
Based on the latest capacity data available from the Petroleum Association of Japan, of the country’s 22 official refineries, the newly integrated company will now control six refineries with a combined capacity of 945,000 b/d, including:
• Idemitsu Kosan’s 160,000-b/d refinery in Chita.
• Idemitsu Kosan’s 190,000-b/d refinery and petrochemical complex in Ichihara.
• Idemitsu Kosan’s 150,000-b/d refinery in Tomakomai.
• The Showa Shell Sekiyu-held Toa Oil’s 70,000-b/d Keihin refinery in Kawasaki.
• The Showa Shell Sekiyu-held Showa Yokkaichi Sekiyu’s 255,000-b/d Yokkaichi refinery in Yokkaichi.
• The Showa Shell Sekiyu-held Seibu Oil’s 120,000-b/d Yamaguchi refinery in Ube.
Idemitsu Kosan also operates the Tokuyama petrochemical complex in Shunan.
Aramco lets contract for unit at Riyadh refinery
Saudi Aramco has let a contract to KBR Inc. to provide technology for a supercritical solvent deasphalting (SDA) unit as part of a residue upgrading and clean fuels project at its 126,000-b/d refinery in Riyadh, Saudi Arabia.
KBR will deliver licensing for its proprietary three-product SDA ROSE technology, including basic engineering design and proprietary equipment for the new unit, which will be designed to meet Aramco’s specific objectives for the project.
The project comes as part of Aramco’s strategy to comply with the new International Marine Organization (IMO) fuel regulations that take effect in January 2020, KBR said.
CPCL lets contract for unit at proposed refinery
Chennai Petroleum Corp. Ltd. (CPCL), a partly owned subsidiary of Indian Oil Corp. Ltd., has let a contract to Chevron Lummus Global (CLG)—a joint venture of McDermott International Inc. and Chevron Corp.—to provide technology licensing for a delayed coking unit at CPCL’s proposed grassroots Cauvery Basin refinery at Nagapattinam in Tamilnadu, India.
Alongside licensing its proprietary delayed coking technology to maximize value from the vacuum residue stream, CLG also will deliver basic engineering design for the planned 50,200-b/d delayed coker, McDermott said.
The service provider valued the contract—which was signed during this year’s first quarter—at $1-50 million.
In its latest annual report to investors, CPCL said it has obtained in-principle approval for the proposed 180,740-b/d Cauvery Basin refinery that, if realized, will play an important role in meeting future energy needs of India’s Tamilnadu state.
According to CPCL, the total project will require an investment of 274.5-274.6 billion rupees (±30%) to complete.
Raven Petroleum plans fractionator for South Texas
Raven Petroleum, The Woodlands, Tex., has received an air permit from the Texas Commission on Environmental Quality for a proposed 30,000-b/d crude fractionation unit in South Texas.
The planned fractionator would allow Raven to produce ultralow-sulfur diesel, stabilized naphtha, and fuel gas, Raven said. The unit is to be sited in Duval County, Tex., at the crossroads of the Permian basin, Wolfcamp, and Eagle Ford shales in proximity to the US Gulf Coast, Mexico, and other US markets.
Raven previously announced plans to build a full 55,000-b/d refinery and energy complex in Duval County, just outside of Laredo, Tex., to refine light, sweet Texas crude from growing shale production in the region.
Raven said it continues to look at other large land positions on the USGC, US Midcontinent, and abroad that could potentially host economically viable refining projects.
Eni, Fiat test low-carbon dioxide vehicle fuel
Eni SPA and Fiat Chrysler Automobiles (FCA) are developing a high-alcohol vehicle fuel that they say can lower exhaust emissions of carbon dioxide by up to 3% under Worldwide Harmonized Light Vehicle Test Procedures. Working under a research contract they entered in 2017, the companies have completed an initial test of the fuel in five rental cars in Milan.
The vehicles ran on “A20” gasoline, which contains 15% methanol and 5% bioethanol. During the 13-month test, the cars were rented about 9,000 times and traveled 50,000 km without experiencing problems. Eni and FCA are working to increase the renewable content of the hydrocarbon component of A20.
The A20 formula is designed to reduce direct and indirect CO2 emissions. It’s compatible with vehicles sold since 2001.
TRANSPORTATIONQuick Takes
Number of pipeline incidents declining, report shows
The number of incidents affecting people has decreased 20% as the total of US mileage and deliveries has increased more than 10% in the last 5 years, the American Petroleum Institute and the Association for Oil Pipelines jointly said in their 2019 Liquids Pipeline Performance Report.
API and AOPL issued the report nearly a week after Democrats and Republicans on the House Transportation and Infrastructure Committee called on the US Pipeline and Hazardous Materials Safety Administration (PHMSA) to implement mandates in the 2011 and 2016 federal pipeline safety law reauthorizations more quickly (OGJ Online, Apr. 8, 2019).
Each year, the two associations download data PHMSA collects and analyze the numbers to see where pipeline operators are making progress, and determine where to focus upcoming industry-wide improvement efforts.
Their latest report found that in the last 5 years:
• Total liquids incidents decreased by 20%.
• Pipeline incidents caused by incorrect operation fell 38%.
• Corrosion, cracking, or weld failure incidents fell 35%.
• Total liquids pipeline mileage rose 12%, including a 30% rise in oil lines, as the number of barrels delivered grew 44%.
Woodside signs 10-year LNG supply deal
Woodside Energy has signed a heads of agreement with Chinese distributor ENN Group for the sale of 1 million tonnes/year of LNG from Woodside for 10 years starting in 2025.
Woodside CEO Peter Coleman signed the deal in Shanghai at the LNG2019 conference saying that the agreement builds on an October 2018 cooperation agreement under which the two companies committed to work together to evaluate a broad range of potential business opportunities.
Coleman added that the HOA demonstrated market support for Woodside’s proposals to expand the Pluto LNG facility on the Burrup Peninsula and develop Scarborough field on the Exmouth Plateau as part of the vision for the Burrup Hub in Western Australia. ENN is keen to increase its market share in China’s gas distribution and retail sector, as well as elsewhere.
The HOA is conditional on the negotiation and execution of a fully termed sales agreement and obtaining all the necessary approvals as well as reaching FID on the Scarborough project.
Tellurian begins open season for PGAP line
Tellurian unit Permian Global Access Pipeline (PGAP) is holding a binding open season to secure prospective shippers for a proposed 42-in. interstate natural gas pipeline connecting the Permian basin in Texas to southwestern Louisiana.
The proposed pipeline will extend 625 miles with the capacity to transport 2 bcfd of gas. With multiple receipt and delivery locations connecting multiple common gathering points and third-party pipelines expected, the pipeline will connect supply sources originating at or near the Waha Hub in Pecos County, Tex., and will deliver gas near Gillis, Jefferson, and Davis parishes in Louisiana. At a cost of $3.7 billion, construction is expected to start as early as 2021 with an in-service target as early as 2023.
PGAP is part of Tellurian’s proposed Tellurian Pipeline Network and incremental to the $15.2-billion investment that Tellurian plans for Driftwood LNG, a proposed LNG export facility near Lake Charles, La.
Pres. and CEO Meg Gentle said, “Permian producers have recently paid $9/MMbtu to move their natural gas away from the wellhead, reflecting the acute need for infrastructure development in the basin. By contrast, Southwest Louisiana is a market expected to grow 300% in the next 5 years.”
The open season runs through May 24.
